CN111527281A - Determining wellbore leak cross-flow between formations in an injection well - Google Patents

Determining wellbore leak cross-flow between formations in an injection well Download PDF

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CN111527281A
CN111527281A CN201880082624.9A CN201880082624A CN111527281A CN 111527281 A CN111527281 A CN 111527281A CN 201880082624 A CN201880082624 A CN 201880082624A CN 111527281 A CN111527281 A CN 111527281A
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injection
well
injection well
pressure
performance model
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纳塞尔·穆巴拉克·阿尔-哈杰里
穆罕默德·D·阿拉-杰米
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Saudi Arabian Oil Co
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Saudi Arabian Oil Co
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/117—Detecting leaks, e.g. from tubing, by pressure testing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells

Abstract

Techniques are described for determining wellbore leak cross flow between formations in an injection well. The technique retards the well performance principle to achieve the goal of quantifying cross flow without running a flowmeter.

Description

Determining wellbore leak cross-flow between formations in an injection well
Priority requirement
This application claims priority from U.S. patent application No.15/805,813, filed on 7/11/2017, the entire contents of which are incorporated herein by reference.
Technical Field
The present description relates to lateral flow analysis in injection wells.
Background
Injection wells are used to flow fluids into a subterranean zone that includes a subterranean formation, a portion of a subterranean formation, or multiple subterranean formations, such as sandstone, limestone, or other formations. The injection fluid may be water, wastewater, brine, water mixed with chemicals, combinations thereof, or other fluids. Injection wells are sometimes used for hydrocarbon recovery. For example, a fluid such as steam, carbon dioxide, water, or other fluid may be injected into a hydrocarbon reservoir to maintain reservoir pressure, or to heat hydrocarbons in the reservoir, thereby allowing hydrocarbons to be recovered from the reservoir. Sometimes, leaks occur inside an injection well, causing fluids to flow through the injection well, particularly through leaks, from a high pressure formation in a subterranean zone to a low pressure formation in another subterranean zone. Such leaks can affect the integrity of the injection well and, in turn, the recovery of hydrocarbons from the hydrocarbon reservoir.
Disclosure of Invention
This specification describes technologies relating to determining wellbore leak cross flow between formations in an injection well.
Certain aspects of the subject matter described herein may be implemented as a method. During normal operation of an injection well formed in a subterranean region, a plurality of bottom hole pressures at a bottom of the injection well are determined based on a respective plurality of surface injection pressures at a surface of the injection well. Each surface injection pressure is a pressure in the injection well resulting from a respective injection flow rate of an injection fluid flowing through the injection well from the surface towards the bottom. Determining an injector well performance model for the injector well based on the plurality of bottom hole pressures and a plurality of injection flow rates. Each injection flow is caused by each of the plurality of surface injection pressures. The injection well is shut off in response to a subsurface leak that results in a cross flow through the injection well from a high pressure region in the subsurface region to a relatively low pressure region in another subsurface region. After shut-down, the shut-down injection well is modeled as an injection well having an injection well performance model determined during normal operation of the injection well. Modeling a shut-down injection well as a production well having an injection well performance model determined during normal operation of the injection well. Determining a cross flow rate in the injection well at a location of a subsurface leak in the injection well based on an injection well performance model of a modeled injection well and an injection well performance model of a modeled production well.
This and other aspects can include one or more of the following features. To model a shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well, an injection index of the injection well during normal operation of the injection well is determined using the injection well performance model. The injection index is a ratio between an injection flow rate of an injection fluid into the injection well and a difference between a bottom hole injection pressure caused by the injection flow rate and a static bottom hole reservoir pressure. Assigning the injection index of the injection well as an injection index of the production well. To determine an injection index for an injection well during normal operation of the injection well using the injection well performance model, a plurality of injection indices are determined based on the plurality of bottom hole pressures and a plurality of injection flow rates and a calibration is performed. To calibrate the plurality of injection indices, a statistical regression analysis is performed on the plurality of injection indices. To determine an injector well performance model for the injector well based on the plurality of bottom hole pressures and the plurality of injection flow rates, a profile of the injector well performance model is determined. The curve represents a bottom-of-well pressure and an injection flow rate of an injection fluid into the injection well at a surface of the injection well. The bottom hole pressure in the curve is determined using the following equation:
Figure BDA0002547977960000021
Figure BDA0002547977960000023
is the surface injection pressure, ρ, for injection flow measurementwIs the density of the injected fluid and,
Figure BDA0002547977960000022
is the deviation angle of the injection well relative to the vertical axis, f is the dimensionless coefficient of friction, gcIs the acceleration due to gravity and d is the inner diameter of the injection well. The injection flow rate in the curve is determined using the following equation: q ═ II (pdowhole inj. — Pr). II is the injectivity index of the injector and Pr is the static bottom hole reservoir pressure of the injector before injector shut-in. In order to model a shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well, a bottom hole pressure of the modeled shut-down injection well is specified to be the same as a bottom hole pressure of the injection well measured during normal operation. To determine a lateral flow rate of a modeled injection well at a location of a subsurface leak in the injection well based on an injection well performance model of the injection well and an injection well performance model of the modeled production well, the location of the subsurface leak in the injection well is designated as a top node of the modeled closed production well. Determining a production flow rate for the modeled shut-in production well at each of the plurality of bottom hole pressures upon which the injector well performance model is determined. Production flow rate is determined using the following equation: q is PI (Pr-Pwf). Q is the production flow, PI is the productivity index of the production well, Pr is the static bottomhole reservoir pressure of the injector during normal operation, Pwf is the flowing bottomhole reservoir pressure at a selected node of subsurface leak depth for the modeled shut-down production well after the injector closes in response to a leak. The productivity index is designated as an injection index of the injection well during normal operation. The injection fluid may be water.
Certain aspects of the subject matter described herein may be implemented as a computer-readable medium (transitory or non-transitory) storing computer instructions executable by one or more processors to perform operations described herein. Certain aspects of the subject matter described herein may be implemented as a system comprising one or more processors and a computer-readable medium (transitory or non-transitory) storing computer instructions executable by the one or more processors to perform operations described herein.
The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
Drawings
Figure 1 is a schematic illustration of an injection well.
Figure 2A is a schematic diagram of a hypothetical injection well with a leak.
FIG. 2B is a schematic illustration of a hypothetical production well with a leak.
Fig. 3 is a flow chart of an example process of determining cross flow in an injection well at a leak location.
Fig. 4A and 4B are flow diagrams of an example process for modeling a leak in an injection well.
Figure 5 is a graph showing a performance model of an actual injection well.
Figure 6 is a graph showing a performance model of a hypothetical injection well.
FIG. 7 is a graph illustrating a performance model of a leaking formation.
FIG. 8 is a graph illustrating a performance model of a hypothetical production well.
Fig. 9 is a graph showing determination of the cross flow amount.
Figures 10A-10E are schematic diagrams of actual and hypothetical injection wells used to model a leak.
FIG. 11 is a high-level architectural block diagram of a computer system for modeling cross flow in an injection well.
Like reference numbers and designations in the various drawings indicate like elements.
Detailed Description
The specification describes determining the amount of cross flow between two formations due to a downhole leak in a water well. Well integrity monitoring is an important aspect of a well's safe production or injection operations. Some well integrity monitoring systems include wellhead tree valve testing, attached base inspection (string base inspection), annulus surveying, and temperature and corrosion logging. When an integrity problem occurs, a workover rig will be used to perform well preparation operations to restore well integrity. A well that is under a leaking cross flow is classified as being in a well control condition. One step of a suitable well integrity diagnosis includes: the leak cross flow is quantified to plan cross flow isolation and subsequent well servicing to ensure safety of such wells. One technique for quantifying cross flow includes: a spinner (e.g., a flow meter) is transported to the leaking subsurface location by cable, coiled tubing, or other transport methods and is used to identify cross flow and cross flow direction. However, such measurements may sometimes be operationally or economically infeasible. This specification describes a method of determining cross flow without the use of such a spinner, but rather using surface data measured during normal operation of the well. By implementing the techniques described herein, well safety design may be optimized while minimizing well intervention, costs associated with operating a spinner downhole may be minimized or avoided, and potential mechanical damage due to well intervention via the spinner may also be minimized or avoided.
As described later, well injection and well shut-in data before and after a leak are used to determine the cross-flow between two formations in a leaking injection well without the need for a spinner or flow meter. To this end, well performance modeling and nodal analysis with respect to the injection well is implemented. Well performance models are always reliable tools to establish well injection or production behavior. The well performance model is particularly effective in water wells because the single-phase flow characteristics of the injector facilitate accurate calculation of dynamic well parameters. Modeling of well performance using nodal analysis may be accomplished by dividing the well system into different segments based on selected nodes.
In some implementations, a cross-flow amount between two formations due to a downhole leak in a water well is calculated. To this end, a real injector well performance model is generated using the pre-leak injection data. The data includes the physical size of the injection well, the latest static bottom hole pressure, and the injection pressure and flow rate. The generated performance model is then calibrated using surface injection pressure and flow data to generate an injection for the actual injection wellAnd (4) index. A hypothetical injection well model is then generated by simulating the flow characteristics and properties of the actual water injector to simulate the leakage cross-flow in a flow (i.e., injection) regime. The hypothetical injection well is assumed to have the same reservoir pressure and injection index as the actual injection well. The hypothetical injector well model has a top node selected to be a leak point. Performance curves of the hypothetical injection well model at different nodal pressures are generated. A performance model of a hypothetical injection well showing an injection pressure-flow curve is plotted. Calculating a flowing injection pressure (P) at the depth of a leak based on the surface injection pressure and flow collected after the leak occurred in the actual wellwfl) A performance model of the leaking formation using the leaked-off injection data may be generated. Determining an injection flow rate (Q) into a downhole formation using a flowing injection pressure at a leak depth and a hypothetical injection well modeldf). Using QdfAnd total injection flow (Q)t) Determining the flow rate (Q) into the leaking formation1). By plotting the flow injection pressure (P)wfl) And flow rate (Q) into the leaking formation1) A performance model of the leaking formation is generated. A hypothetical production well model is generated by simulating the flow characteristics and properties of an actual water injector to simulate the leakage cross-flow in the shut-down condition. The hypothetical production well is modeled as having the same reservoir pressure as the actual injection well. The production rate index of the hypothetical production well is assumed to be equal to the injection index of the actual injection well. Generating a hypothetical production flow (Q) from the downhole formation into the leaking formationip). The system node of the hypothetical production well is selected to be at the leak point. The flow injection pressure (P) is then plottedwfl) And flow rate (Q) from the downhole formation into the leaking formationip)。Pwfl-Q1Curve and Pwfl-QipThe intersection of the curves is the cross flow into the leak.
Implementations of the techniques described herein may provide the ability to design a well control method in the event of a case leak in a pipeless (tubing-less) injector without running a flowmeter survey. Implementations may also allow conventional well performance modeling principles to be re-determined to calculate cross-flow based on pre-leak and post-leak surface injection data and knowledge of previous leak depths. In addition to eliminating costs associated with intervention, implementations of the techniques described herein may also reduce risks associated with in situ well intervention.
Fig. 1 is a schematic illustration of an injection well 102. Injection well 102 is formed by extending from the surface through a subterranean region into formation 104. Wellhead 106 is located at the surface of injection well 102. During normal operation, injection fluid (e.g., water or other fluid) flows from the surface through the injection well 102 into the formation 104. During normal operation, an injector well performance model for the injector well 102 is generated to correlate the injection flow rate of injection fluid into the injector well 102 with the bottom hole flow pressure of the injector well 102. A process for determining an injector well performance model is described with reference to fig. 3, which is an example process 300 of determining cross flow in an injector well at the location of a leak.
At 302, a plurality of bottom hole pressures at the bottom of the injection well 102 are determined based on a respective plurality of surface injection pressures at the surface of the injection well 102. Each surface injection pressure is the pressure in the injection well that results from the respective injection flow rate through the injection well 102 from the surface toward the bottom.
In some implementations, an orifice plate may be used to determine the injection flow rate. An orifice plate is located in a surface tubing connected to a wellhead 106 of the injection well 102 and is used to measure injection data, including injection fluid flow rates and injection wellhead pressures at the surface of the injection well 102. For example, the volumetric injection fluid flow rate entering the injection well at the surface may be a pressure differential upstream and downstream of the orifice plate using equation 1.
Figure BDA0002547977960000061
In equation 1, Q is the volumetric flow rate (e.g., in barrels per day (bbls)), d1Is the inner diameter (e.g., in inches), d, of a conduit connected to the wellhead 106 of the injection well 102 through which the fluid flows2Is the hole diameter (e.g., in inches) of the holes in the orifice plate, P1Is the injection fluid pressure upstream of the orifice plate (e.g., in pounds per square inch)In units of (psi), P2Is the injection fluid pressure (e.g., in psi) downstream of the orifice plate, and ρwIs the density of the injected fluid (e.g., in pounds mass per cubic foot). The injection fluid pressure upstream and downstream of the orifice plate may be measured using one or more pressure sensors installed at one or more appropriate locations in the injector well string 102, respectively.
Injection wellhead pressure is measured using a pressure sensor (e.g., a manometer or other pressure sensor) installed at the wellhead 106. The amount and flow rate of injection fluid through injection well 102 may be varied, for example, by operating injection fluid pumps of different capacities. For each quantity, a respective injection wellhead pressure may be measured, and a respective volumetric injection fluid flow rate may be calculated using equation 1. The measured injection wellhead pressure and the calculated volumetric injection fluid flow rate may then be used to determine the bottom hole pressure at the bottom of the injection well 102, as described below.
At 304, an injector well performance model for the injector well is determined based on the plurality of bottom hole pressures and the plurality of injection rates into the well. A plurality of bottom hole pressures at the bottom of the injection well are determined using equations 2 and 3.
Figure BDA0002547977960000071
Figure BDA0002547977960000072
In the case of the equation 2, the,
Figure BDA0002547977960000073
is the downhole injection pressure (e.g., in psi),
Figure BDA0002547977960000074
is wellhead injection pressure (e.g., in psi), Δ PgIs the incremental pressure of gravity (e.g., in psi), and Δ PfIs the friction delta pressure (e.g., in psi). In equation 3Measuring wellhead injection pressure and using equation
Figure BDA0002547977960000075
Representing the gravitational force exerted by the injected water, where pwIs the density of the injected fluid (e.g., water or other single-phase fluid). Angle phi is the borehole offset angle measured relative to the vertical axis, and D is the depth of the injection well (e.g., in feet). In addition, in equation 3, the friction incremental pressure is the equation
Figure BDA0002547977960000076
Measured, wherein f is the dimensionless coefficient of friction, gcIs the acceleration due to gravity (32.2ft/sec) and d is the inner diameter of the conduit through which the injection fluid in the injection well 102 flows.
In this manner, an injector performance model of the injector 102 is determined during normal operation of the injector 102 to correlate the volumetric injection flow rate (Q) and the bottom hole flow pressure (P) at the bottom of the injector 102. The injection well performance model describes the subsurface fluid flow of water into the formation 104 and the corresponding injection index. By varying the volumetric injection flow rate, different bottom hole flow pressures may be calculated, and the volumetric injection flow rate and bottom hole flow pressure may be used to plot an injector performance model generated for the injector 102.
To model the shut-down injector as a hypothetical production well with an injector performance model determined during normal operation of the injector 102, the injection index of the injector 102 is determined using equation 4.
Figure BDA0002547977960000077
In equation 4, Q is the volumetric flow rate determined using equation 1 (e.g., in barrels per day (bbls)),
Figure BDA0002547977960000081
is the downhole injection pressure (e.g., in psi) determined using equations 2 and 3, and PrIs the static bottom hole (reservoir) pressure measured before the injector well 102 is shut-in.
The injection index is the ratio between the injection flow rate of the injection fluid into the injection well and the difference between the downhole injection pressure and the static bottomhole reservoir pressure resulting from the injection flow rate. During normal operation, the injection index of the injector well 102 is periodically calculated from the pressure drop measurements. The bottom hole pressure caused by the surface injection pressure may change over time for the same well, for example, due to the continuous application of pressure through the well. Fig. 5 is a graph 500 illustrating a performance model of an actual injection well. The X-axis of the graph 500 is flow rate in barrels per day, while the Y-axis of the graph 500 is injection pressure in pounds per square inch (psi). The graph relates surface injection pressure and surface injection flow rate directly proportional to each other. Knowledge of this relationship between injection pressure and fluid flow rate helps determine the injection index of an injection well. In some implementations, a calibration operation (described later) may be implemented to calibrate the injector well performance model.
At 306, after injector shut-in, the shut-in injector is modeled as an injector having an injector performance model of the injector determined as previously described. To this end, an injection well that models the flow characteristics and properties of an actual water injector is modeled (e.g., by computational modeling) to simulate a leakage cross flow under flow (injection) conditions. Fig. 2A is a schematic of a hypothetical injection well 202 with a leak in the injection well 102 that results in a cross flow through the injection well 102 from a high pressure region (e.g., formation 104) to a relatively low pressure region (e.g., formation 204) in a subterranean region. The subsurface location of the leak is designated as the top node 206 of the hypothetical injection well. In other words, the hypothetical injection well is considered to have the same physical dimensions as injection well 102, and to have an injection wellhead at the leak depth, and the total depth of the well is from the leak depth to formation 104. For example, the location of the leak may be identified by reducing mechanical drift tools conveyed into the closed injection well 102 via wireline intervention. Additionally, it is assumed that the fluid injected into the well is an injection fluid, i.e., water or other single-phase fluid that flows from high pressure formation 104 to low pressure formation 204 in a steady state.
As described above, the hypothetical injection well is assigned the same reservoir pressure and injection index as the actual injection well. The hypothetical injection well model has a top node selected to be at a leak point, and the performance curves are generated at node pressures of different systems. Equations 3 and 4 are used for this modeling. Fig. 6 is a graph 600 illustrating a performance model of a hypothetical injection well. The X-axis of graph 600 is flow rate in barrels per day, while the Y-axis of graph 600 is injection pressure in pounds per square inch (psi). The graph relates injection pressure and injection flow rate directly proportional to each other. Knowledge of this relationship between injection pressure and fluid flow rate helps determine the injection index of an injection well.
At 308, after the injection well is shut in, the shut in injection well is modeled as a production well having the same well performance model as the injection well determined as previously described. To this end, a production well is modeled (e.g. by computational modeling) that models the flow characteristics and properties of an actual water injector to simulate a leakage cross flow in a flow (injection) regime. Fig. 2B is a schematic of a hypothetical production well 208 with a leak in the injection well 102 that results in a cross flow through the injection well 102 from a high pressure region (e.g., the formation 104) to a relatively low pressure region (e.g., the formation 204) in the subsurface region. The subsurface location of the leak is designated as the top node 210 of the hypothetical production well. In other words, the hypothetical production well is considered to have the same physical dimensions as the injection well 102, and to have an injection wellhead at the leak depth, and the total depth of the well is from the leak depth to the formation 104. For example, the location of the leak may be identified by reducing mechanical drift tools conveyed into the closed injection well 102 via wireline intervention. Additionally, assume that the fluid produced from the well is an injection fluid, i.e., water or other single-phase fluid that flows from high pressure formation 104 to low pressure formation 204 in a steady state.
As described above, the hypothetical production well is assigned the same reservoir pressure and injection index as the actual injection well. The hypothetical injection well model has a top node selected to be at a leak point, and the performance curves are generated at node pressures of different systems. A new curve is determined for the hypothetical production well using the productivity index assigned to the hypothetical production well. As previously described, the top node of the hypothetical production well model is designated as the subsurface location of the leak. The cross flow rate in the injection well 102 at the subsurface location is then determined using equation 5.
Figure BDA0002547977960000091
In equation 5, Q is the production flow (i.e., the cross flow through the leaking subterranean location), PrIs the static bottom hole (reservoir) pressure measured before the injector well 102 is shut off,
Figure BDA0002547977960000092
is the bottom hole injection pressure (e.g., in psi) of the leaking formation of the well having the well parameters (i.e., depth, inside diameter) of the hypothetical production well. Specifically, because the leakage depth of the hypothetical production well is the same as the depth of the injection well 102, the bottom hole injection pressure determined for the hypothetical production well will be the same as the bottom hole injection pressure determined for the injection well 102. Thus, the cross flow rate through the leaking subsurface location will also be different than the volumetric flow rate at the surface of the injection well 102. Fig. 6 is a graph 600 illustrating a performance model of a hypothetical injection well. The X-axis of graph 600 is flow rate in barrels per day, while the Y-axis of graph 600 is injection pressure in pounds per square inch (psi).
Fig. 4A and 4B are flow diagrams of an example process of modeling leaks in an injection well (e.g., injection well 102). At 402, during normal operation of an injection well, a plurality of injection flows are received. At 404, a plurality of surface injection pressures are received. At 406, a plurality of bottom hole pressures are determined based on the surface injection pressure and the injection flow rate. At 408, the flow of injection fluid through the injection well is modeled. Process step 402, process step 404, process step 406, and process step 408 are implemented in a substantially similar manner as process step 302 and process step 304 previously described with reference to flowchart 300 of fig. 3.
At 410, after an injection well shutdown in response to a subsurface leak, the shut down injection well is modeled as an injection well having the same model as an injection well during normal operation. To this end, at 412, the subsurface location of the leak is designated as the top node of the modeled injection well. Process steps 410 and 412 are implemented in a substantially similar manner as process step 306 previously described with reference to flowchart 300 of fig. 3. The output of process step 412 is the graph 600 previously described with reference to fig. 6.
At 414, a performance model of the hypothetical injection well is plotted, which shows an injection pressure-flow curve. A performance model is generated using the leaked injection data. The surface injection pressure and flow rate collected after a leak in the actual injection well is used to calculate the flow injection pressure (P) at the depth of the leakwfL). Total injection flow (Q) measured at the surfacet) There are two parts: a portion enters the leaking formation (Q)L) Another part enters the underground formation (Q)DF). Then, by adding PwfLCalculating Q using a synthetic well model as wellhead pressure for a synthetic injection wellDF. Using the principle of conservation of mass and assuming an incompressible fluid (i.e., constant density), Q is determined using equation 6LQuantization is performed.
QL＝QT-QDF(equation 6)
Then, P is drawnwfLAnd QLTo generate a model of the performance of the leaking formation. The output of process step 414 is graph 700 (fig. 7). The X-axis shows the volumetric flow (Q) into the leaking formation1) The Y-axis shows the pressure (P) at the depth of the leak in barrels per daywf1)。
At 416, after injector shut-down in response to a subsurface leak, the shut-down injector is modeled as a production well having the same model as the injector during normal operation. To this end, at 418, the subsurface location of the leak is designated as the top node of the modeled production well. At 420, the flow injection pressure (P) is plottedwfl) With respect to flow rate (Q) from the downhole formation into the leaking formationip) E.g. as graph 800 (graph)8) As shown therein.
At 422, the intersection of the curve determined at 414 (e.g., curve 700) and the curve determined at 420 (e.g., curve 800) is determined as the amount of cross flow into the leaking formation. Fig. 9 is a graph 900 illustrating the determination of cross flow.
The above technique is summarized below with reference to fig. 10A-10E, which are schematic diagrams of actual and hypothetical injection wells that model the leak. Fig. 10A is a schematic diagram of an actual injection well under normal injection conditions. Fig. 10B is a schematic diagram of an injection well in a cross-flow injection state. Fig. 10C is a schematic view of a virtual injection well in a virtual injection state. FIG. 10D is a schematic illustration of a hypothetical production well under hypothetical production conditions. Figure 10E is a schematic of an actual injection well in a cross-flow shut-off condition. The surface of the virtual well (fig. 10C and 10D) is the same as the leakage depth of the crossflow in the actual injection well (fig. 10E). The leakage can be modeled by performing the following steps.
First, a performance model of an actual injection well may be generated using pre-leak injection data obtained by performing the previously described measurements in the actual injection well, schematically illustrated in fig. 10A. The physical dimensions of the actual injection well, the latest static bottom hole static pressure, and the injection pressure and injection flow rate are used to model the performance of the downhole formation using equations 3 and 4. The generated performance model is then calibrated using wellhead (surface) injection pressure and flow data. The output of this model will generate an injection index for the actual injection well.
Second, a hypothetical injection well model is generated (fig. 10C). The hypothetical injection well simulates the flow characteristics and properties of an actual water injector to simulate a leaking cross flow in a flow (injection) regime. The hypothetical injection well has the same reservoir pressure and injection index as the actual injection well. The hypothetical injection well model has a top node selected to be at a leak point, and the performance curves are generated at node pressures of different systems. Equations 3 and 4 are suitable for this modeling.
Third, a performance model of the leaking formation is generated using the post-leak injection data (fig. 10B). Will be in the actual injection wellThe surface injection pressure and flow rate collected after the occurrence of a leak are used to calculate the flow injection pressure (P) at the depth of the leakwfL). Total injection flow (Q) measured at the surfacet) There are two parts: a portion enters the leaking formation (Q)L) Another part enters the underground formation (Q)DF). Then, by adding PwfLCalculating Q using a synthetic well model as wellhead pressure for a synthetic injection wellDF. Using the principle of conservation of mass and assuming an incompressible fluid (i.e., constant density), Q is determined using equation 6LQuantization is performed. Then, P is drawnwflAnd QLTo generate a model of the performance of the leaking formation.
Fourth, a hypothetical production well model is generated (fig. 10D). Production wells are envisaged that simulate the flow characteristics and properties of a real injector to simulate a leakage cross flow in the off state. The hypothetical production well has the same reservoir pressure as the actual injection well and the productivity index of the hypothetical production well is assumed to be equal to the injection index of the actual injection well. The hypothetical production flow rate from the downhole formation into the leaking formation is referred to as QIP and is generated according to equations 3 and 5. Selecting a system node of a hypothetical production well to be located at a leak point and for QIPDrawing Pwfl. The intersection points of the two curves generated according to the third and fourth steps are plotted together, the intersection points being the operating system node pressure and flow rate corresponding to the cross flow rate in the off state (fig. 10E).
FIG. 11 is a high-level architectural block diagram of a computer system 1100 for modeling cross flow in an injection well. At a high level, computer system 1100 includes a flow response computer system 1100 communicatively coupled to a network 1150. The network 1150 facilitates communication between the components of the system 1100 and other components. Computer system 1100 may receive requests from client applications over network 1150 and respond to received requests by processing the requests in the appropriate software application. Additionally, requests may also be sent to computer system 1100 from internal users (e.g., from a command console or by another suitable access method), external or third parties, other automation applications, and any other suitable entity, person, system, or computer.
Computer system 1100 is configured to model cross flow in an injection well. In some cases, computer system 1100 is configured to implement process 300 or process 400 (or both) in executable computing code (e.g., C/C + + executable code), an application program (e.g., EXCEL), or another other computer.
Computer system 1100 may include a computer that includes input devices (e.g., a keypad, keyboard, touch screen, microphone, voice recognition device, other device capable of accepting user information), or output devices that convey information associated with the operation of the computer, including digital data, visual or audio information, or a GUI.
Each of the components of the computer system 1100 may communicate using a system bus 1103. In some implementations, any or all of the components (both hardware and software) of the computer system 1100 can interface with each other or the interface 1104 via the system bus 1103 using an Application Programming Interface (API)1112 or a service layer 1113.
Computer system 1100 includes an interface 1104. Although illustrated in fig. 11 as a single interface 1104, two or more interfaces 1104 may be used according to particular needs, desires, or particular implementations of the computer system 1100. Interface 1104 is used by computer system 1100 to communicate with other systems in a distributed environment (whether shown or not) connected to a network 1150.
Computer system 1100 includes one or more processors (e.g., processor 1105). Although illustrated in fig. 11 as a single processor 1105, two or more processors may be used depending on the particular needs, desires, or particular implementation of the computer system 1100. In general, the processor 1105 executes instructions and manipulates data to perform the operations described herein.
Computer system 1100 also includes memory 1106 that stores data for computer system 1100. Although illustrated in fig. 11 as a single memory 1106, two or more memories may be used depending on the particular needs, desires, or particular implementation of the computer system 1100. Although memory 1106 is shown as an integrated component of computer system 1100, in alternative implementations, memory 1106 may be external to computer system 1100.
Implementations and operations of the subject matter described in this specification can be implemented in digital electronic circuitry, or in computer software, firmware, or hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Implementations of the subject matter described in this specification can be implemented as one or more computer programs, i.e., one or more modules of computer program instructions, encoded on a computer storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively or in addition, the program instructions may be encoded on an artificially generated propagated signal (e.g., a machine-generated electrical, optical, or electromagnetic signal) that is generated to encode information for transmission to suitable receiver apparatus for execution by a data processing apparatus. The computer storage medium may be, or be included in, a computer-readable storage device, a computer-readable storage substrate, a random or serial access memory array or device, or a combination of one or more of them. Further, although the computer storage medium is not a propagated signal, the computer storage medium can be a source or destination of computer program instructions encoded in an artificially generated propagated signal. The computer storage medium may also be, or be included in, one or more separate physical components or media (e.g., multiple CDs, disks, or other storage devices).
The operations described in this specification can be implemented as operations performed by data processing apparatus on data stored on one or more computer-readable storage devices or received from other sources.
The term "data processing apparatus" includes all types of apparatus, devices, and machines for processing data, including by way of example a programmable processor, a computer, a system on a chip, or a plurality or combination of the foregoing. The apparatus can comprise special purpose logic circuitry, e.g., an FPGA (field programmable gate array) or an ASIC (application-specific integrated circuit). The apparatus can include, in addition to hardware, code that creates a runtime environment for the computer program in question, e.g., code that constitutes processor firmware, a protocol stack, a database management system, an operating system, a cross-platform runtime environment, a virtual machine, or a combination of one or more of the foregoing. The apparatus and execution environment may implement a variety of different computing model infrastructures, such as web services, distributed computing and grid computing infrastructures.
A computer program (also known as a program, software application, script, or code) can be written in any form of programming language, including: a compiled or interpreted language, declarative or procedural language, and the computer program may be deployed in any form, including as a stand-alone program or as a module, component, subroutine, object, or other unit suitable for use in a computing environment. The computer program may, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data (e.g., one or more scripts stored in a markup language document), in a single file dedicated to the program in question, or in multiple coordinated files (e.g., files that store one or more modules, sub programs, or portions of code). A computer program can be deployed to be executed on one computer or on multiple computers that are located at one site or distributed across multiple sites and interconnected by a communication network.
The processes and logic flows described in this specification can be performed by one or more programmable processors executing one or more computer programs to perform actions by operating on input data and generating output. The processes and logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, e.g., an FPGA (field programmable gate array) or an ASIC (application-specific integrated circuit).
Processors suitable for the execution of a computer program include, by way of example, both general and special purpose microprocessors, and any one or more processors of any kind of digital computer. Generally, a processor will receive instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a processor for performing actions in accordance with instructions and one or more memory devices for storing instructions and data. Generally, a computer will also include, or be operatively coupled to receive data from and/or transmit data to, or both, one or more mass storage devices for storing data, e.g., magnetic, magneto-optical disks, or optical disks. However, the computer need not have these devices. Further, the computer may be embedded in another device, e.g., a mobile telephone, a Personal Digital Assistant (PDA), a mobile audio or video player, a game player, a Global Positioning System (GPS) receiver, or a portable storage device (e.g., a Universal Serial Bus (USB) flash drive). Devices suitable for storing computer program instructions and data include all forms of non-volatile memory, media and memory devices, including by way of example semiconductor memory devices, EPROM, EEPROM, and flash memory devices; magnetic disks (e.g., internal hard disks or removable disks); magneto-optical disks; as well as CD ROM discs and DVD-ROM discs. The processor and the memory can be supplemented by, or incorporated in, special purpose logic circuitry.
Thus, particular implementations of the present subject matter have been described. Other implementations are within the scope of the following claims. In some cases, the actions recited in the claims can be performed in a different order and still achieve desirable results. In addition, the processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results. In some implementations, multitasking and parallel processing may be advantageous.

Claims (20)

1. A method, comprising:
during normal operation of an injection well formed in a subterranean region, determining a plurality of bottom hole pressures at a bottom of the injection well based on a respective plurality of surface injection pressures at a surface of the injection well, each surface injection pressure being a pressure in the injection well resulting from a respective injection flow rate of an injection fluid through the injection well from the surface toward the bottom;
determining an injector well performance model for the injector well based on the plurality of bottom hole pressures and a plurality of injection flow rates, wherein each injection flow rate is caused by each surface injection pressure of the plurality of surface injection pressures;
after closing an injection well in response to a subsurface leak in the injection well, wherein the leak results in a cross flow through the injection well from a high pressure region in the subsurface region to a relatively low pressure region in another subsurface region:
modeling a shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well;
modeling the shut-down injection well as a production well having an injection well performance model determined during normal operation of the injection well; and
determining a cross flow rate in the injection well at a location of a subsurface leak in the injection well based on an injection well performance model of a modeled injection well and an injection well performance model of a modeled production well.
2. The method of claim 1 wherein modeling the shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well comprises:
determining an injection index of the injection well during normal operation of the injection well using the injection well performance model, wherein the injection index is a ratio between an injection flow rate of an injection fluid into the injection well and a difference between a downhole injection pressure caused by the injection flow rate and a static bottomhole reservoir pressure; and
designating the injection index of the injection well as an injection index for the production well.
3. The method of claim 2 wherein determining an injection index for the injection well during normal operation of the injection well using the injection well performance model comprises:
determining a plurality of injection indices based on the plurality of bottom hole pressures and a plurality of injection flow rates; and
calibrating the plurality of injection indices to determine the injection index.
4. The method of claim 3, wherein calibrating the plurality of injection indices comprises performing a statistical regression analysis on the plurality of injection indices.
5. The method of claim 1, wherein determining an injector well performance model for the injector well based on the plurality of bottom hole pressures and the plurality of injection flow rates comprises: determining a curve of the injection well performance model, wherein the curve represents a bottom hole pressure and an injection flow rate of an injection fluid into the injection well at a surface of the injection well.
6. The method of claim 5, wherein the bottom hole pressure in the curve is determined using the equation:
Figure FDA0002547977950000021
Figure FDA0002547977950000022
wherein P isWHinjIs the surface injection pressure, ρ, for injection flow measurementwIs the density of the injected fluid and,
Figure FDA0002547977950000023
is the offset angle of the injection well relative to a vertical axis, f is the dimensionless coefficient of friction, gcIs the acceleration due to gravity and d is the inner diameter of the injection well.
7. The method of claim 6, wherein the injection flow in the curve is determined using the equation: q ═ II (Pdownhole inj. -Pr), where II is the injectivity index of the injector and Pr is the static bottomhole reservoir pressure of the injector before it closes.
8. The method of claim 2, wherein modeling the shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well comprises: the bottom hole pressure of the modeled shut-down injector is designated as the same as the bottom hole pressure of the injector measured during normal operation.
9. The method of claim 1, wherein determining the cross flow rate in the injection well at a location of a subsurface leak in the injection well based on an injection well performance model of a modeled injection well and an injection well performance model of a modeled production well comprises:
determining a first flow injection pressure (P) for a modeled closed injection well using surface injection pressures and flow rates acquired after a leak in an actual injection wellwfl1) And a corresponding first flow (Q) into said locationL)；
Determining a second flow injection pressure (P) for the modeled shut-in production wellwfl2) And a corresponding second flow rate (Q) from a downhole location in the subterranean zone into the location of the subterranean leakIP) (ii) a And
determining Pwfl1-QLCurve of (a) and Pwfl2-QIPThe intersection of the curves of (a).
10. The method of claim 9, wherein determining the second flow injection pressure and corresponding second flow rate comprises:
designating a location of the subsurface leak in the injection well as a top node of the modeled shut-in production well; and
determining a production flow rate for the modeled shut-in production well at each of a plurality of bottom hole pressures, determining the injector well performance model based on each of the plurality of bottom hole pressures, wherein the production flow rate is determined using the following equation: q ═ PI (Pr-Pwf), where Q is the production flow rate, PI is the productivity index for the producer, Pr is the static bottomhole reservoir pressure for the injector during normal operation, Pwf is the flowing bottomhole reservoir pressure for the modeled shut-down producer at a selected node located at subsurface leak-down depth after closure of the injector in response to a leak, where the productivity index is specified as the injection index for the injector during normal operation.
11. The method of claim 1, wherein the injection fluid is water.
12. A computer-readable medium storing instructions executable by one or more processors to perform operations comprising:
during normal operation of an injection well formed in a subterranean region, receiving a plurality of bottom hole pressures at a bottom of the injection well based on a respective plurality of surface injection pressures at a surface of the injection well, each surface injection pressure being a pressure in the injection well resulting from a respective injection flow rate of an injection fluid through the injection well from the surface toward the bottom;
determining an injector well performance model for the injector well based on the plurality of bottom hole pressures and a plurality of injection flow rates, wherein each injection flow rate is caused by each surface injection pressure of the plurality of surface injection pressures;
after closure of an injection well responsive to a subsurface leak in the injection well, wherein the leak results in a cross flow through the injection well from a high pressure region in the subsurface region to a relatively low pressure region in another subsurface region:
modeling a shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well;
modeling the shut-down injection well as a production well having an injection well performance model determined during normal operation of the injection well; and
determining a cross flow rate in the injection well at a location of a subsurface leak in the injection well based on an injection well performance model of a modeled injection well and an injection well performance model of a modeled production well.
13. The medium of claim 12, wherein modeling the shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well comprises:
determining an injection index of the injection well during normal operation of the injection well using the injection well performance model, wherein the injection index is a ratio between an injection flow rate of an injection fluid into the injection well and a difference between a downhole injection pressure caused by the injection flow rate and a static bottomhole reservoir pressure; and
assigning an injection index for the injection well as an injection index for the production well.
14. The medium of claim 13, wherein determining the injection index of the injection well during normal operation of the injection well using the injection well performance model comprises:
determining a plurality of injection indices based on the plurality of bottom hole pressures and a plurality of injection flow rates; and
calibrating the plurality of injection indices to determine the injection index.
15. The medium of claim 14, wherein calibrating the plurality of injection indices comprises performing a statistical regression analysis on the plurality of injection indices.
16. The medium of claim 12, wherein determining an injector well performance model for the injector well based on the plurality of bottom hole pressures and the plurality of injection flow rates comprises: determining a curve of the injection well performance model, wherein the curve represents a bottom hole pressure and an injection flow rate of an injection fluid entering the injection well at a surface of the injection well.
17. The medium of claim 16, wherein the bottom hole pressure in the curve is determined using the equation:
Figure FDA0002547977950000041
Figure FDA0002547977950000051
wherein
Figure FDA0002547977950000052
Is the surface injection pressure, ρ, for injection flow measurementwIs the density of the injected fluid and,
Figure FDA0002547977950000053
is the offset angle of the injection well relative to a vertical axis, f is the dimensionless coefficient of friction, gcIs the acceleration due to gravity and d is the inner diameter of the injection well.
18. The medium of claim 17, wherein the injection flow rate in the curve is determined using the equation: q ═ II (Pdownhole inj. -Pr), where II is the injectivity index of the injector and Pr is the static bottomhole reservoir pressure of the injector before it closes.
19. The medium of claim 13, wherein modeling the shut-down injection well as an injection well having an injection well performance model determined during normal operation of the injection well comprises: the bottom hole pressure of the modeled shut-down injector is designated as the same as the bottom hole pressure of the injector measured during normal operation.
20. The medium of claim 12, wherein determining the cross flow rate in the injection well at a location of a subsurface leak in the injection well based on an injection well performance model of a modeled injection well and an injection well performance model of a modeled production well comprises:
determining a first flow injection pressure (P) for a modeled closed injection well using surface injection pressures and flow rates acquired after a leak in an actual injection wellwfl1) And a corresponding first flow (Q) into said locationL)；
Determining a second flow injection pressure (P) for the modeled shut-in production wellwfl2) And a corresponding second flow rate (Q) from a downhole location in the subterranean zone into the location of the subterranean leakIP) (ii) a And
determining Pwfl1-QLCurve of (a) and Pwfl2-QIPThe intersection of the curves of (a).
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